Note : Les descriptions sont présentées dans la langue officielle dans laquelle elles ont été soumises.
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METHOD OF ENHANCING DRILLING FLUID PERFORMANCE
BACKGROUND OF THE INVENTION
1. Field of the Invention
[0001] The present invention relates to methods of enhancing drilling fluid
performance. More particularly, the present invention relates to enhancing
drilling fluid
performance where foam is used as at least part of the drilling fluid.
2. Description of Related Art
[0002] Hydrocarbons, such as oil and gas, may be recovered from various
types of
subsurface geological formations. Such formations typically consist of a
porous layer, such
as limestone and sands, overlaid by a nonporous layer. Hydrocarbons cannot
rise through
the nonporous layer, and thus, the porous layer forms a reservoir in which
hydrocarbons are
able to collect. A well is drilled through the earth until the hydrocarbon
bearing formation
is reached. Hydrocarbons then are able to flow from the porous formation into
the well.
[0003] In conventional drilling processes, a drill bit is attached to a
series of pipe
sections or coiled drilling tubing referred to as the drill string. The drill
string terminates in
a drill tool, which cuts a borehole through the different formations. The
drill string is
gradually lengthened as the drill tool cuts the borehole. Additionally,
drilling in the
borehole is also utilized in well completion and production operations, such
as drilling out
packers utilized during well casing operations and workover operations.
[0004] As a wellbore is drilled, the production of hydrocarbons from
hydrocarbon
producing formations must be controlled until the well is completed and the
necessary
production equipment has been installed. The most common way of controlling
production
during the drilling process is to circulate a drilling fluid. Typically, the
drilling fluid is
pumped down the drill string, through the drill tool, and into the wellbore.
The hydrostatic
pressure of the drilling fluid in the wellbore relative to the hydrostatic
pressure of
hydrocarbons in the formation is adjusted by varying the density of the
drilling fluid,
thereby controlling the flow of hydrocarbons from the formation.
[0005] In addition to controlling hydrostatic pressure, drilling fluids are
used for a
variety of other purposes. The drilling fluid also helps stabilize uncased
portions of the
wellbore and prevents it from caving in. Large quantities of cuttings are
generated during
drilling. As it is re-circulated back up the wellbore, the drilling fluid also
carries cuttings
away from the drill tool and out of the wellbore. Also when rotary drill tools
or drill bits are
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used, a tremendous amount of heat can be generated as the drill string is
rotated and the bit
cuts through the earth. The drilling fluid serves to lubricate and cool the
drill bit.
[0006] Traditionally, drilling fluids have most commonly been high-density
dispersions
of fine, inorganic solids, such as clay and barite, in an aqueous liquid or
hydrocarbon liquid.
These drilling fluids have traditionally been called drilling mud and the
drilling has been
conducted in an overbalanced condition; that is, the hydrostatic pressure of
drilling fluid in
the wellbore exceeds the pressure of hydrocarbons in the formation.
Hydrocarbons,
therefore, are prevented from flowing into the wellbore. This avoids the risk
that the well
will blow-out and damage the environment and drilling equipment or injure
those working
on the drilling rig.
[0007] A major consequence of overbalanced drilling operations is that
drilling fluid
can flow from the wellbore into the formation. That flow of fluid at
relatively low levels is
referred to as seepage and, at higher levels, as lost circulation. Seepage,
and especially lost
circulation, in turn may have several deleterious and costly effects. First,
any drilling fluid
that flows into the formation must be replaced in order to maintain
circulation of fluid
through the well. The amount and cost of drilling fluid required to drill the
well, therefore,
is increased.
[0008] Second, seepage and lost circulation of drilling fluid can carry
with it the
cuttings and many of the other components in the drilling fluid, which can
decrease the
permeability of the formation. Thus, it becomes more difficult for oil to flow
from the
formation once drilling is completed and production is started. Decreased
permeability also
may require acidizing or fracturing the hydrocarbon bearing formation to
enhance
production from the formation, which will further increases costs.
[0009] The problems associated with seepage and lost circulation may be
addressed by
adjusting the density of the drilling mud. The density of the drilling mud may
be controlled
by the amount of solids added and, therefore, adjusted to balance the
hydrostatic pressures
at the interface between the wellbore and the formation. Seepage and lost
circulation and
their attendant problems also may be addressed by the formation of a filter
cake on the wall
of the wellbore or by the addition of filtration control and seepage control
additives
designed to physically impede the flow of fluid into the wellbore.
[0010] While drilling mud is suitable for use in a wide variety of
hydrocarbon bearing
formations, in many formations the hydrostatic pressure of hydrocarbons in the
formation is
relatively low and many drilling muds are simply too heavy for low pressure
formations.
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They can significantly overbalance the well, allowing excessive amounts of
drilling fluid to
flow into the formation. The problems caused by seepage and lost circulation
are
exacerbated when a low pressure formation is also relatively fragile, such as
fractured
limestone formations. Fragile formations may be excessively fractured by the
hydrostatic
pressure of drilling fluid flowing into the formation and carry even more
materials into the
formation that will diminish its permeability. Seepage and lost circulation
materials, in
particular, if they are carried into the formation, can cause extensive damage
to the
formation.
[00111 Accordingly, it is often preferable to drill through formations that
are highly
permeable, that have low pressures, or that are fragile in a near balanced or
underbalanced
state. That is, the hydrostatic pressure of the fluid in the wellbore will be
approximately
equal to or less than the hydrostatic pressure of the formation, and various
lower density
drilling fluids have been developed for such purposes. Such drilling fluids,
known as drill-
in fluids, are specially designed to minimize formation damage when drilling
into reservoir
sections. Drill-in fluids may be an aqueous brine containing only selected
solids of
appropriate particle size ranges (salt crystals or calcium carbonate) and
polymers.
Generally, additives in drill-in fluids have been limited to ones essential
for filtration
control and cuttings carrying. Accordingly, these drill-in fluids have
included a bridging
agent designed to form a filter cake, which is external to the formation and
which can easily
be removed during the completion phase.
[0012] Such drill-in fluids may still be too heavy for use in extremely low-
pressure,
fragile formations without substantial losses. Lower densities have been
achieved by using
foamed drill-in fluids. They typically comprise a surfactant solution with gas
dispersed
therein. The surfactant acts to stabilize the gas dispersion. For
environmental reasons,
aqueous systems are preferred, and they typically include a polymer to improve
the
rheological and thixotropic properties of the foam.
[0013] In general, such foamed drill-in fluids perform quite well in
drilling operations
and offer several advantages over traditional suspended solids drilling
fluids, For example,
the density of the foam may be controlled relatively easily by adjusting the
gas injected into
the foam. Also, the ability of foamed drill-in fluids to carry cuttings away
from a drilling
bit is much greater than that of liquid drilling fluids. More effective
removal of cuttings
allows drilling to proceed at a faster pace, thereby reducing the time and
expense of drilling.
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Moreover, when used at near balanced or underbalanced conditions, foamed drill-
in fluids
can effectively prevent damage to even highly fragile, highly permeable
formations.
[0014] Foamed drill-in fluids are prepared by mixing a liquid phase, such
as a polymer-
surfactant solution, and a gas phase, such as nitrogen. Typically, this has
been done by high
velocity mixing of the phases or by injecting gas into the liquid phase
through a small
orifice. Most commonly, the foam is generated at the surface and then pumped
into the
wellbore. It also has been suggested that drill-in fluids may be foamed by
pumping separate
liquid and gas streams through a drill string to a downhole foam generator.
[0015] Both generating foam at the surface and below the surface, by use of
separate
streams, entail significant cost. The foamed drill-in fluids require a source
of gas such as
nitrogen and various additional equipment that are not needed in conventional
liquid
circulation systems. For example, if liquid nitrogen is used, special tanks
and equipment for
cryogenically storing and handling the liquid nitrogen are required. Foam
circulation
systems also may include compressors, storage tanks, air pumps, foam
generators, and other
equipment beyond that commonly employed for circulating liquids. Moreover,
unlike many
other drilling fluids which are hydraulic, foamed drill-in fluids are
pneumatic. Special
pneumatic pumps and control heads may have to be used to pump or otherwise
control the
foam in the wellbore. Thus, systems for preparing and circulating foamed drill-
in fluids are
relatively costly and require more maintenance, control, and logistical
support than those
required for more traditional suspended solids drilling fluids.
[0016] Such problems are exacerbated in offshore drilling operations where
maintenance and logistical support are more difficult and costly. Space also
is at a premium
in offshore operations. On land, there usually is adequate space for
additional equipment.
Offshore, however, valuable space on the drilling rig deck is required, or it
may be
necessary to provide a barge or support boat to accommodate a foam circulation
system.
That can add considerable cost to the drilling operation.
[0017] It is therefore desirable to enhance the performance of foamed drill-
in fluids and
reduce the cost of the application of foamed drill-in fluids.
SUMMARY OF THEN INVENTION
[0018] The present invention relates to methods of generating gas downhole
during
drilling operations so as to produce a foamed drill-in fluid downhole between
the drill tool
and the wellbore.
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[0019] In one embodiment, the present invention provides a method of
drilling in a
wellbore comprising the steps of providing a drill-in fluid comprising an
aqueous fluid, a
foaming agent, a foam stabilizer, a gas generating chemical and an
encapsulated activator;
introducing the drill-in fluid downhole into a drill string connected to a
drill tool wherein
both the gas generating chemical and the encapsulated activator are admixed
into the drill-in
fluid prior to introduction into the drill string; and allowing the drill-in
fluid to exit the drill
tool where, upon exiting the drill tool, the encapsulated activator is de-
capsulated
sufficiently to react with the gas generating chemical such that a gas is
generated within the
drill-in fluid and thus foams the drill-in fluid.
[0020] In another embodiment, the present invention provides a method of
drilling in a
wellbore comprising the steps of providing a drill-in fluid consisting
essentially of an
aqueous fluid, a foaming agent, a foam stabilizer, a gas generating chemical
and an
encapsulated activator; introducing the drill-in fluid downhole into a drill
string connected
to a drill tool wherein the aqueous fluid, the foaming agent, the foam
stabilizer, the gas
generating chemical and the encapsulated activator are all admixed into the
drill-in fluid
prior to introduction into the drill string; and allowing the drill-in fluid
to exit the drill tool
where, upon exiting the drill tool, the encapsulated activator is de-
capsulated sufficiently to
react with the gas generating chemical such that a gas is generated within the
drill-in fluid
and thus foams the drill-in fluid.
DESCRIPTION OF THE PREFFERRED EMBODIMENTS
[0021] The present invention provides improved methods of generating gas in
and
foaming a drill-in fluid upon the drill-in fluid's exiting the drill tool;
that is, while the drill-
in fluids are passing from the interior to the exterior of the drill tool and
while the drill-in
fluid is in the region between the drill tool and the borehole where drilling
of the formation
is occurring. In accordance with the invention, the drill-in fluid comprises
an aqueous fluid,
a foaming agent, a foam stabilizer, a gas generating chemical and an
encapsulated activator.
Additionally, the drill-in fluid can comprise a water soluble viscosifier, a
fluid loss control
additive and a bridging agent. The viscosifier, fluid loss control additive
and bridging agent
are optional and depend upon the specific application; however, it is a
distinct advantage of
the current invention that the drill-in fluid described herein will have a
reduced need for
fluid loss control additives, viscosifying agents and/or bridging agents.
Accordingly, for
many applications, the drill-in fluid will not contain these components and,
indeed, the
inventive drilling process will be carried out without the use of
viscosifiers, fluid loss
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control additives and bridging agents other than as those functions are
carried out by one or
more of the aqueous fluid, foaming agent, foam stabilizer, gas generating
chemical and an
encapsulated activator as present in the foamed drilling fluid. Thus, in one
embodiment of
the invention, the drill-in fluid consists essentially of an aqueous fluid, a
foaming agent, a
foam stabilizer, a gas generating chemical and an encapsulated activator. It
should be
understood that for the components of the drill-in fluid, the use of singular
foul's of "a,"
"an" and "the" include plurals and thus encompass one or more of the listed
components.
[0022] The aqueous fluid of the drill-in fluid can be any aqueous liquid
capable of
forming a solution with the other components of the drill-in fluid. The term
"solution" as
used herein, encompasses dispersions, emulsions, or any other substantially
homogeneous
mixture, as well as true solutions. The solvent preferably is either fresh
water or an aqueous
brine. Generally, the aqueous liquid can make up from about 80 percent to
about 98 percent
of the drill-in fluid by weight.
[0023] The gas generating chemicals useful in accordance with this
invention will react
with the activator in aqueous solutions to generate a gas, which may be
selected from the
group consisting of carbon dioxide, oxygen, sulfur dioxide, nitrogen, nitrogen
dioxide,
ammonia, and mixtures thereof, or consisting of any subgroup of the foregoing.
Generally,
gas generating chemicals that react to generate primarily carbon dioxide or
nitrogen are
preferred. While the gas generating chemicals will generally produce one
primary gas, they
can also produce one or more secondary gases. For example, those that
primarily generate
nitrogen can also generate small amounts of ammonia depending on the chemical
structure
of the gas generating chemical and the activator or activating agent. Thus,
when the
nitrogen gas generating chemical molecule contains amide groups, additional
ammonia,
carbon dioxide (an acidic gas), and carbon monoxide may be produced.
[0024] In order to cause the gas generating chemicals to generate gases,
one or more
encapsulated activators are combined with the drill-in fluid containing one or
more gas
generating chemicals. The encapsulated activator can have a pre-selected
release time or
temperature such that the activator becomes de-capsulated after a pre-selected
amount of
time in the drill-in fluid or after the drill-in fluid reaches a pre-selected
temperature;
however, it is preferred that the encapsulated activator have a release
associated with the
high shear conditions at the drill tool. Accordingly, in one embodiment, the
encapsulation
material releases or de-capsulates the activator when the drill-in fluid
undergoes the shear
conditions at the drill tool and/or in the region between the drill tool and
borehole. The
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conditions in these regions are what is known as high shear conditions and
will be greater
shear conditions than experienced by the drill-in fluid prior to entering the
drill tool from
the drill string. The release or de-capsulation should be sufficient so that
enough activator
reacts with the gas generating chemical so as to generate gas sufficient to
foam the drill-in
fluid to a predetermined level or density. In this manner, the encapsulated
activator can be
released without relying on time or temperature release encapsulating means.
[0025] Generally and as described below, the gas generating chemicals will
be a
reducing agent and the encapsulated activator will be an oxidizing agent.
However, it is
within the scope of the invention for the gas generating chemical to be the
oxidizing agent
and the encapsulated activator to be the reducing agent. Thus, while the
compounds below
are listed as either a gas generating chemical or as an encapsulated
activator, it should be
understood that this is how they will typically be utilized in the invention
but they can serve
as either as long as there is both a reducing agent and an oxidizing agent;
that is, a reducing
compound can serve as the encapsulated activator as long as an oxidizing agent
serves as
the gas generating chemical. In this regard, because solid compounds can be
easier to
encapsulate, generally a solid compound will be chosen as the encapsulated
activator.
[0026] Nitrogen gas generating chemicals which can be utilized in
accordance with the
methods of the present invention include, but are not limited to, compounds
containing
hydrazine or azo groups, for example, hydrazine, azodicarbonamide, azobis
(isobutyronitrile), p-toluene sulfonyl hydrazide, p-toluene sulfonyl
semicarbazide,
carbohydrazide, p-p' oxybis (benzenesulfonylhydrazide) and mixtures thereof.
Additional
examples of nitrogen gas generating chemicals which do not contain hydrazine
or azo
groups and which are also useful in the present invention include, but are not
limited to,
ammonium salts of organic or inorganic acids, hydroxylamine sulfate, carbamide
and
mixtures thereof. Of these, azodicarbonamide or carbohydrazide are preferred.
[0027] The generation of gas from the nitrogen gas generating chemicals
depends on the
structure of the gas generating chemicals. When the chemical contains an azo
group
containing two nitrogens connected by a double bond as in azodicarbonamide,
the gas
generation is caused either thermally or by reaction with alkaline reagents.
The reactions
with the azocarbonamide generate ammonia gas and possibly carbon dioxide and
release the
doubly charged diimide group. The diimide dianion being chemically unstable
decomposes
to nitrogen gas.
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[0028] The gas generating chemicals containing hydrazide groups in which
the two
nitrogen atoms are connected by a single bond as well as connected to one or
two hydrogens
produce gas upon reaction with an oxidizing agent. It is believed that the
oxidizing agent
oxidizes the hydrazide group to azo structure. Therefore, hydrazide materials
containing
two mutually single bonded nitrogens, which in turn are also bonded to one or
more
hydrogens, need oxidizing agents for activation. To enhance the water
solubility of such
materials, alkaline pH is generally required. Occasionally, additional
chemicals may be
needed to increase the rate of gas production.
[0029] Examples of delayed encapsulated activators suitable for use with
nitrogen gas
generating chemicals include, but are not limited to, alkaline materials such
as carbonate,
hydroxide and oxide salts of alkali and alkaline earth metals such as lithium,
sodium,
magnesium and calcium and oxidizing agents such as alkali and alkaline earth
metal salts of
peroxide, persulfate, perborate, hypochlorite, hypobromite, chlorite,
chlorate, iodate,
bromate, chloroaurate, arsenate, antimonite and molybdate anions. Specific
examples of the
oxidizing agents include ammonium persulfate, sodium persulfate, potassium
persulfate,
sodium chlorite, sodium chlorate, hydrogen peroxide, sodium perborate and
sodium peroxy
carbonate. Other examples of oxidizers which can be used in the present
invention are
disclosed in U.S. Pat. No. 5,962,808 issued to Landstrom on October 5, 1999,
Of the
various activators that can be used, sodium or ammonium persulfate and sodium
chlorite are
preferred. The actual amounts of the alkaline material used in the well
treating fluid should
be sufficient to maintain the pH of the fluid between 10 and 14.
[0030] Carbon dioxide gas generating chemicals can be selected from the
group
consisting of organic acids and inorganic acids, and mixtures thereof. Organic
acids
suitable for use as the gas generating chemical can be selected from the group
consisting of
carboxylic acids, acetic acids, acetyl salicylic acids, ascorbic acids, citric
acids, lactic acids,
tartaric acids, gluconic acids, phenyl glycolic acids, benzylic acids, malie
acids, salicylic
acids, formic acids, propionic acids, butyric acids, oleic acids, linoleic
acids, linolenic acids,
sorbic acids, benzoic acids, phenyl acetic acids, gallic acids, oxylacetic
acids, valeric acids,
palmitic acids, fatty acids, valproic acids, acrylic acids, and methacrylic
acids, and mixtures
thereof, or consisting of any subgroup of the foregoing. Inorganic acids
suitable for use as
the gas generating chemical can be selected from the group consisting of
hydrochloric acids,
sulfuric acids, nitric acids, sulfonitric acids, polyphosphoric acids,
chlorosulfuric acids, and
boric acids, and mixtures thereof, or consisting of any subgroup of the
foregoing. Most
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preferably, the second foam generating agent is 2-hydroxy-1,2,3-
propanetricarboxylic acid,
citric acid, or mixtures thereof.
[0031] Encapsulated activators suitable for use with carbon dioxide gas
generating
chemicals include, but are not limited to, acid and neutral salts of alkali
metals and alkaline
earth metals, and mixtures thereof, or consisting of any subgroup of the
foregoing. The
encapsulated activator can be selected from the group consisting of sodium
bicarbonate,
potassium bicarbonate, calcium bicarbonate, barium bicarbonate, and lithium
bicarbonate,
and mixtures thereof, or consisting of any subgroup of the foregoing.
[0032] The activators can be encapsulated with various materials which
delay their
reaction with the gas generating chemical or chemicals used. Solid activators
can be
encapsulated by spray coating a variety of materials thereon. Such coating
materials
include, but are not limited to, waxes, drying oils such as tung oil and
linseed oil,
polyurethanes and cross-linked partially hydrolyzed polyacrylics. Often,
because of the
oxidizing and corrosive nature of the activators, an additional undercoat of
polymeric
materials such as styrene butadiene can be deposited on the solid activator
particles prior to
depositing the slow releasing polymeric coating. Generally, the encapsulating
material is
chosen so that sufficient release of the activator under the shear conditions
at and around the
drill tool will be achieved to provide release of sufficient gas to adequately
foam the drill-in
fluid a predetermined amount.
[0033] In general the amount of gas generating chemical and encapsulated
activators
used in the drill-in fluid will depend on the amount of gas desired and,
hence, the amount of
foaming desired. The gas generating chemical or chemicals utilized are
combined with the
well treating fluid in a general amount, depending on the amount of gas
desired under
downhole conditions, in the range of from about 0.1 percent to about 10
percent by weight
of the drill-in fluid. The activator or activators used and their amounts are
selected for the
activator's ability to cause the gas generating chemical or chemicals to
generate gas at a
particular temperature or range of temperatures, generally the temperature or
range of
temperatures at the drill tool. The temperatures at which various activators
cause a
particular gas generating chemical to produce gas can be readily determined in
the
laboratory. The amount of the activator included in the well treating fluid in
the
encapsulated form range from about 0.1 percent to about 10 percent by weight
of the drill-in
fluid.
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[0034] In
addition to the gas generating chemicals and encapsulated activators, a
mixture of foaming and foam stabilizing surfactants can be combined with the
drill-in fluid
to facilitate the formation and stabilization of the drill-in fluid foam
produced by the
liberation of gas therein. Generally, these foaming and foam stabilizing
surfactants will be
present in an amount from 0.01 percent to 10 percent by weight of the drill-in
fluid, and can
be present in an amount from 0.1 percent to 2 percent by weight of the drill-
in fluid. An
example of such a mixture of foaming and foam stabilizing surfactants is
comprised of an
ethoxylated alcohol ether sulfate surfactant, an alkyl or alkene amidopropyl
betaine
surfactant and an alkyl or alkene amidopropyldimethylamine oxide surfactant.
Additional
examples of foaming agents include betaines; amine oxides; methyl ester
sulfonates;
alkylamidobetaines, such as cocoamidopropyl betaine; alpha olefin sulfonate;
trimethyltallowammonium chloride; C8-C22 alkyl etho xyl ate
sulfates; and
trimethylcocoammonium chloride. Additional examples of foam stabilizers
include fatty
methyl ester surfactants, aliphatic alkyl sulfonate surfactants, aliphatic
alkyl sulfate
surfactants, a nanoparticle, and combinations thereof.
[0035] A water
soluble viscosifier or gelled fluid can be used to adjust the viscosity of
the drill-in fluid and/or to help increase foam stability. The viscosifier can
be selected from
the group consisting of water soluble starches and modified versions thereof,
water-soluble
polysaccharides and modified versions thereof, water soluble celluloses and
modified
versions thereof, water soluble polyacrylamides and copolymers thereof, and
combinations
thereof. Other examples of suitable viscosifiers include biopolymers such as
xanthan and
succinoglycan, cellulose derivatives such as hydroxyethylcellulose and guar
and its
derivatives such as hydroxypropyl guar. Water soluble viscosifiers can be
present in an
amount from about 0.01 percent to about 3 percent by weight of the drill-in
fluid.
[0036] If used,
a variety of fluid loss control additives may be included in the drill-in
fluid, including starch, starch ether derivatives, hydroxyethylcellulose,
cross-linked
hydroxyethylcellulose, and mixtures thereof. In certain preferred embodiments,
the fluid
loss control additive is starch. The fluid loss control additive is present in
the drill-in fluid
in an amount sufficient to provide a desired degree of fluid loss control,
More particularly,
the fluid loss control additive is present in the drill-in fluid in an amount
in the range of
from about 0.01 percent to about 3 percent by weight.
[0037] Bridging
agents may optionally be used. Bridging agents are generally solids
added to a drilling fluid to bridge across the pore throat or fractures of an
exposed rock
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thereby preventing loss of drilling fluid or excessive filtrate. Fluid loss
control additives
and bridging agents achieve a somewhat similar result; however, generally
fluid loss control
additives form a seal or filter cake to seal off the flow channel or path into
the surrounding
reservoir or rock without any substantial penetration and bridging materials
have some
degree of invasion or penetration into the pore space to mechanically bridge
off or seal the
reservoir or rock. Bridging materials are commonly used in drilling fluids and
in lost
circulation treatments. For reservoir applications, the bridging agent should
be removable.
Common products include calcium carbonate (acid-soluble), suspended salt
(water-soluble)
or oil-soluble resins. For lost circulation treatments, any suitably sized
products can be used,
including mica, nutshells and fibers. These products are also referred to as
lost circulation
material (LCM).
[0038] If used, the bridging agent can comprise solid particulates or a
degradable
material and can be present in the drill-in fluid in an amount sufficient to
create an efficient
filter cake. In certain embodiments, the bridging agent comprised of the
degradable material
is present in the well drill-in fluid in an amount ranging from about 0.1
percent to about 3
percent by weight. Examples of solid particulates to be used as bridging agent
include latex
polymer, graphite, calcium carbonate, dolomite, celluloses, micas, sand or
ceramic particles.
The degradable material comprises a degradable polymer or a dehydrated
compound.
Examples of the degradable polymer include polysaccharides, chitins,
chitosans, proteins,
orthoesters, aliphatic polyesters, poly(glycolides), poly(lactides), poly(s-
caprolactones),
poly(hydroxybutyrates), polyanhydrides, aliphatic polycarbonates,
poly(orthoesters),
poly(amino acids), poly(ethylene oxides), or polyphosphazenes. Examples of the
dehydrated compound include anhydrous sodium tetraborate or anhydrous boric
acid.
[0039] Thus, a method in accordance with one embodiment of the invention
starts with
providing a drill-in fluid comprising an aqueous fluid, a foaming agent, a
foam stabilizer, a
gas generating chemical and an encapsulated activator. As mentioned above, the
drill-in
fluid can have other components such as fluid loss control agents, bridging
agents and/or
viscosifying agents; however, it is an advantage of the invention that the
need for such
additional agents is reduced or eliminated. Accordingly, in another embodiment
the drill-in
fluid provided consists essentially of an aqueous fluid, a foaming agent, a
foam stabilizer, a
gas generating chemical and an encapsulated activator and the method in
accordance with
the invention does not rely on any substantial amounts of additional fluid
loss control
agents, bridging agents and/or viscosifying agents.
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[0040] After an aqueous fluid, a foaming agent, a foam stabilizer, a gas
generating
chemical and an encapsulated activator have been combined to produce the drill-
in fluid, the
drill-in fluid is introduced downhole into and through a drill string
connected at its
downhole end to a drill tool. Accordingly, both the gas generating chemical
and the
encapsulated activator are admixed into the drill-in fluid prior to
introduction into the drill
string. While one or the other of the gas generating and encapsulated
activator can be
introduced into the drill-in fluid after the rest of the drill-in fluid has
been introduced
downhole, this would eliminate several advantages of the current invention and
increase
cost associated with the use of the drill-in fluid. For example, admixing the
encapsulated
activator downhole just prior to the drill tool would require a separate
stream for the
encapsulated activator and increase the cost and amount of equipment needed .
The current
invention does not need such separate streams for the components of the drill-
in fluid;
rather, all the components can be admixed at the surface and introduced into
the drill string
together.
[0041] When the drill-in fluid reaches the drill tool it flows through the
drill tool and
exits into the wellbore (or borehole) in the region between the borehole wall
and the drill
tool. The drill tool can be most common types of downhole drill tools, such as
a drill bit or
jet drill. Drill bits or rotary drills are conventional drill tools that use
teeth on the drill head
to crush or grind up rock. Generally, drill bits are hollow and have jets to
allow for the
expulsion of drilling fluid. The operation of the drill bit causes high shear
regions within
the hollow interior of the drill bit, at the jets and teeth of the drill bit
and in the region
outside the drill bit between the borehole wall and the drill bit where the
drilling action is
occurring to grind or drill rock or other substances. Thus, upon exiting the
drill bit, the
encapsulated activator is de-capsulated or released by shearing action
sufficiently to react
with the gas generating chemical such that a gas is generated within the drill-
in fluid and
thus foams the drill-in fluid at the drill bit teeth and between the drill bit
and the borehole
wall. While it is within the scope of the invention for all or part of the de-
capsulation to
occur by a delayed encapsulation in which temperature or time of exposure to
other
compounds, such as the aqueous fluid, result in de-capsulation or release of
the activator,
such embodiments are subject to timing miscalculations and can result in the
foaming of the
drill-in fluid prior to reaching the drill bit or after the drill-in fluid has
moved uphole from
the region between the drill bit and the borehole. Accordingly, it is
preferred that the de-
capsulation be performed by the shearing action at and around the drill bit.
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[0042] "Jet drills" as used herein is used to refer to both conventional
jet drills and
hydrajets, unless otherwise indicated. Such jet drills release or jet a fluid
through nozzles
on the drill head, thus creating a high-velocity stream of fluid. Hydrajets
use a fluid,
typically an aqueous fluid, carrying small abrasive particles. The high-
velocity or high
pressure abrasive carrying fluid erodes or abrades away the rock. Conventional
jet drills
typically use drill-in fluid without added abrasives for the high-velocity
stream. In the
current invention, the drill-in fluid described above can be used with or
without abrasives in
hydrajet or conventional jet drilling tools. In both hydrajet and conventional
jet drilling
tools there are high shear conditions at the nozzles and in the region outside
the jet drill
between the borehole wall and the jet drill where the drilling action is
occurring to abrade or
erode rock or other substances. Thus, upon exiting the jet drill the
encapsulated activator is
de-capsulated or released by shearing action sufficiently to react with the
gas generating
chemical such that a gas is generated within the drill-in fluid and thus foams
the drill-in
fluid between the jet drill and the borehole wall.
[0043] After the drill-in fluid exits the drill tool, the thus created
foamed drill-in fluid is
circulated around the region between the drill tool and the borehole wall;
thus cooling and
lubricating the drill tool (typically with drill bits) and entraining drill
cuttings into the
foamed drill-in fluid. The drill-in fluid is further circulated into an
annulus formed between
the wellbore and the drill string such that drill cuttings produced during
drilling are carried
by the foamed drill-in fluid back to the surface via the annulus. The foamed
drill-in fluid is
recovered from the annulus, generally at the surface and the foamed drill-in
fluid is then
defoamed to form a defoamed drill-in fluid. Generally, to improve economics
and
efficiency, the drill-in fluid will be reused. Accordingly, the drill cuttings
and other
impurities can be removed from the drill-in fluid before, during or after
defoaming.
Subsequently, the defoamed and clean drill-in fluid will be admixed with
additional
amounts of the gas generating agent and additional amounts of the encapsulated
activator to
replace these components that were used downhole. The thus formed
recirculation drill-in
fluid is re-introduced into the drill string to thus repeat the use of the
drill-in fluid as
described above. Generally, the drill-in fluid will be recycled downhole many
times with
some fresh drill-in fluid added as necessary to make up for drill-in fluid
lost during the
operation.
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EXAMPLE
[0044] The following prophetic example illustrates the use of one
embodiment of the
inventive drill-in fluid in association with an oil well drilling process.
[0045] First, fresh water, potassium chloride (a clay stabilizer),
cocoamidopropyl
betaine (a foaming agent), an alkyl amidopropyldimethylamine oxide surfactant
(a foam
stabilizer), azodicarbonamide (a nitrogen gas generating chemical), and
ammonium
persulfate encapsulated with polyurethane (an encapsulated activator) are
mixed together on
the surface at a well site to produce a drill-in fluid at the well site. The
drill-in fluid
comprises approximately 92 percent by weight of the aqueous fluid,
approximately 1.0
percent by weight of the foaming agent, approximately 4.0 percent by weight of
the gas
generating chemical and approximately 3.0 percent by weight of encapsulated
activator.
[0046] The drill-in fluid is then introduced downhole into and through a
drill string
penetrating the well bore and connected at its downhole end to a jet drill. As
the drill-in
fluid reaches the jet drill it flows through the hollow interior of the jet
drill and through the
jets on the end of the jet drill where it exits into the wellbore (or
borehole) in the region
between the borehole wall and the jet drill. As the drill-in fluid exits the
jet drill, the
encapsulated activator is de-capsulated by shearing action sufficiently to
react with the gas
generating chemical such that a gas is generated within the drill-in fluid and
thus foams the
drill-in fluid at the jet drill teeth and between the jet drill and the
borehole wall.
[0047] After the drill-in fluid exits the jet drill, the thus created
foamed drill-in fluid is
circulated around the region between the jet drill and the borehole wall; thus
cooling and
lubricating the jet drill and entraining drill cuttings into the foamed drill-
in fluid. The drill-
in fluid is further circulated into an annulus formed between the wellbore and
the drill string
such that drill cuttings produced during drilling are carried by the foamed
drill-in fluid back
to the surface via the annulus. The foamed drill-in fluid is recovered from
the annulus at the
surface and the foamed drill-in fluid is then defoamed to form a defoamed
drill-in fluid.
The drill cuttings and other impurities are removed from the drill-in fluid
after the fluid is
defoamed. The defoamed drill-in fluid is then recycled (by addition additional
amounts of
the gas generating agent and encapsulated activator) and recirculated into the
drill string
where it is again used as described above. The drill-in fluid is successfully
recycled
downhole many times.
[0048] It will be seen that the method of the current invention is well
adapted to carry
out the ends and advantages mentioned as well as those inherent therein. While
the
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presently preferred embodiment of the invention has been shown for the
purposes of this
disclosure, numerous changes in the arrangement and construction of parts may
be made by
those skilled in the art. All such changes are encompassed within the scope
and spirit of the
dependent claims.
